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Responding to Trends in the U.S. Electricity Sector

Sue Tierney, ChairDave Grossman, Rapporteur

2 0 1 4 E N E R G Y P O L I C Y F O R U M

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Responding to Trends in the U

.S. Electricity Sector

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2014 Energy Policy Forum

Sue Tierney, Chair

David Grossman, Rapporteur

Energy and Environment Program

For additional copies of this report, please contact:

The Aspen InstitutePublications Office109 Houghton Lab LaneP.O. Box 222Queenstown, MD 21658Phone: (410) 820-5326Fax: (410) 827-9174E-mail: [email protected]: www.aspeninstitute.org/eee

For all other inquiries, please contact:

The Aspen InstituteEnergy and Environment ProgramOne Dupont Circle, NWSuite 700Washington, DC 20036-1193Phone: (202) 736-2907Fax: (202) 467-0790

Copyright © 2014 by The Aspen Institute

The Aspen InstituteOne Dupont Circle, NWSuite 700Washington, DC 20036-1193

Published in the United States of America in 2014By The Aspen Institute

All rights reserved

Printed in the United States of America

14/013ISBN: 0-89843-XXX

David MonsmaExecutive Director

Nicole AlexievDeputy Director

John A. RiggsSenior Fellow

Avonique De VignesProject Assistant

Timothy OlsonSenior Project Manager

Foreword . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . v

Executive Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

EPA’s Clean Air Act Rules for Carbon Emissions from Power Plants . . . 5

Fuel Choices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

Distributed Energy Resources and the Grid . . . . . . . . . . . . . . . . . . . . . . . . 21

Models for Providing Energy Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

Regulation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

Appendices

Agenda. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45

Participants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49

Table of Contents

The Aspen Institute’s second annual Energy Policy Forum, held in the summer of 1978, focused on natural gas and concluded, “the natural and supplemental sources of gas energy are potentially plentiful and should continue to play a significant part in America’s energy mix.”

The third annual Forum in 1979 considered “Decentralized Electricity and Cogeneration Options,” concluding that “decentral-ized systems will come into increasing use” and that “public policy should be altered to permit this competition.”

The thirteenth annual Forum, in the summer of 1989, discussed global climate change and concluded, “enough is known now to set in motion certain steps (to) reduce emissions of CO

2 and/or other

greenhouse gases.”

It is unlikely that many of the participants in those forums could foresee how long it would take for their conclusions and recom-mendations to take effect, but in 2014 the 38th annual Forum, “Responding to Trends in the Electricity Sector,” revisited all of these issues. The Environmental Protection Agency’s proposed rule on CO

2 emissions from existing electric power plants poses a chal-

lenge to utilities just as they are dealing with, among other challeng-es, the impact of surging production of cheap gas and virtually flat demand and revenue, due in part to distributed energy resources.

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Foreword

The Forum used brief introductory presentations and moder-ated dialogue among a diverse and knowledgeable group of energy experts to consider a range of public policy and business choices fac-ing the electricity sector. The Forum’s rule against quoting anyone by name or affiliation, honored in this report, encouraged a candid and spirited discussion.

Sue Tierney, Managing Principal of The Analysis Group and for-mer Assistant Secretary of Energy for Policy, chaired the Forum. Her deep and varied experience with the industry was helpful in devel-oping the Forum agenda. Her moderating skill, her understanding of the issues, and her good nature enabled her to manage effectively a potentially contentious dialogue.

Highly qualified and informative speakers provided a wealth of information and a variety of perspectives, and the diverse expertise of the participants contributed substantially to the richness of the dialogue.

The Aspen Institute acknowledges and thanks the following Forum sponsors for their financial support. The majority have been participants and supporters for many years. Without their generos-ity and belief in the value of our work, the Forum could not have taken place.


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American Electric Power

The Boyd FoundationDentonsDuke EnergyEdison Electric InstituteGEInstitute for Energy InnovationItron

Pepco

Navigant ConsultingNational Rural Electric Cooperative AssociationNexantUniversity of Texas Energy InstituteUNS Energy

Foreword

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David Grossman again wrote the Forum report. No written report can capture all the depth and nuance of a multi-day conver-sation among participants with various views and areas of expertise, but he has captured the key points of a fast-moving conversation and distilled them into this admirable summary.

Avonique DeVignes handled the logistics of the Forum and responded to the needs of participants, hiding the challenges she faced behind an unfailingly cheerful demeanor. She was ably assisted by Timothy Olson, who preceded her in this role for several years. I am grateful for their dedication and support.

This report is issued under the auspices of the Aspen Institute. The chairs, speakers, participants, and sponsors are not responsible for its contents. It is an attempt to represent ideas and information presented during the Forum, but not all views could be included, the views expressed were not unanimous, and participants were not asked to agree to the wording of the report.

John A. (Jack) Riggs Senior Fellow Energy and Environment Program


David GrossmanRapporteur

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Executive Summary

New federal regulations, changes in fuel prices and trends, the expansion of distributed energy resources, declines in U.S. electricity consumption, and advances in technology are all spurring utilities and regulators to respond and adapt. Discussions of the challenges and opportunities these forces present for the U.S. electricity sec-tor – as well as how the industry and its regulators are adapting – formed the heart of the 2014 Aspen Institute Energy Policy Forum. This report summarizes and organizes some of the key insights from those discussions.

Among the newest and highest-profile of the forces the sector is dealing with is the U.S. Environmental Protection Agency’s pro-posed rule for carbon dioxide emissions from existing fossil-fuel fired power plants, issued under section 111(d) of the Clean Air Act. The rule proposes to set long-term, rate-based carbon intensity goals for each state and then give the states enormous flexibility to meet them. If implemented, the rule, which is designed to follow where the energy world is already heading, is likely to spur improved efficiency at coal-fired power plants, greater use of natural gas-fired power plants, increased deployment of renewable energy and per-haps nuclear power, and increased demand-side energy efficiency. The rule is only a draft, and there are many issues that still need to be clarified and on which the agency is seeking comments. Even in its draft form, though, the rule has spurred conversations in and across states about clean energy, fuel switching, emission reductions,


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and compliance approaches. Further guidance or meetings may be needed to foster collaboration and coordination among the wide range of affected actors before the rule gets finalized.

If the 111(d) rule is following where the energy industry is already heading, it has to account for the numerous cross-currents in the industry that are affecting existing facilities and future fuel choices. Due to the shale revolution, the United States has rather suddenly developed an abundance of inexpensive natural gas that is steadily gaining market share in power generation. That market share is largely coming at the expense of coal, and it is expected that a large amount of coal-fired generation will be retired over the next decade – and that pretty much no new coal plants will get built. The heavy reliance on gas carries some risks, but gas’s central role in the U.S. power system of the 21st century is a near certainty. That power system will also depend heavily on renewable energy sources, which have combined with gas to account for virtually all new U.S. gen-eration capacity in recent years. Gas can support renewables with nimble and fast ramping capability, and the two sources have many potential synergies over the near- and long-term. The future of nuclear power is very uncertain, though, as this zero-carbon source suffers economically in a low-gas-price environment and has an aging fleet. Energy efficiency, however, is cheap, abundant, and low-risk, and efficiency technologies continue to make great strides. Energy efficiency is considered by many to be the first “fuel” to choose.

At the same time, expectations of what the grid can and should deliver are changing, with emerging interest in environmental sus-tainability, resilience, flexibility, and customer control. It is in this context that distributed energy resources such as demand response, solar photovoltaics, advanced metering infrastructure, microgrids, and energy storage are increasingly being deployed. Those utiliz-ing distributed energy resources generally still rely on the grid for backup. As these resources expand, there will be a need to figure out how to value energy, capacity, and grid services separately, how to integrate distributed resources into the grid, and how to ensure the grid continues to provide the reliability and convenience customers want. There are a variety of models and principles being discussed


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for how best to accomplish these goals, how to structure the broader distribution market platform, and what role utilities should play in that system.

Utility strategies have evolved continually over the years in response to what was going on in the world. Many of the past and present pressures on the industry, including the federal 111(d) rule, have not fundamentally altered the underlying business of utilities, but slowing retail electricity sales growth and increased competition from technology do pose potentially fundamental threats to the util-ity business model. Utilities now need to understand and respond to customer choice, which is a challenge for an industry that has lim-ited experience in that area. Utilities can choose to play defense in the face of these pressures, making incremental changes, or they can play offense and pursue new revenue streams, new business models, and new products and services.

Utilities generally cannot create new business models on their own, however. Regulators also play a critical role in facilitating new models, as well as in promoting conversations about the regula-tory compact, the changing grid, and the evolving suite of energy resources. Many times, regulators and the regulatory process act as obstacles to change, but regulators have an opportunity now to adapt to changing circumstances and pursue specific detailed efforts that can help create the right incentives for new business models and broader system efficiency. Regulators can also lead the way by pursuing fundamental redesigns of the entire electricity regulatory system, such as the pioneering effort getting underway in New York that may be every bit as important and impactful as the federal 111(d) rule.

In early June 2014, the U.S. Environmental Protection Agency (EPA) released its proposed rule for carbon dioxide (CO

2) emissions

from existing fossil-fuel fired power plants, issued under section 111(d) of the Clean Air Act (CAA). Driven by President Obama’s desire to take action on climate change and his recognition that Congress will not do so, the EPA’s draft 111(d) rule – dubbed the Clean Power Plan – represents a creative but mission-driven effort to reduce carbon pollution. It will be finalized on June 2, 2015, fol-lowing a lengthy comment period, which will condense the time the EPA has to address the comments and make changes (so the earlier comments are submitted to the EPA, the better).

The rule builds on the tremendous gains made since the CAA’s bipartisan enactment in 1970 and bipartisan amendment in 1990. By 2012, the United States. had achieved 60-80% reductions from 1970 levels for the six main pollutants (PM10, PM2.5, SO

2, CO,

VOC, and NOx) while growing the economy and keeping retail energy prices stable. These are successes we do not celebrate nearly enough – and that we can now begin to replicate with CO

2.

Approach of the 111(d) Rule

The proposed rule is the embodiment of cooperative federalism, with the EPA setting state goals and then giving states maximum

EPA’s Clean Air Act Rules for Carbon Emissions from Power Plants

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flexibility to meet them. The rule was designed to follow where the energy world is already heading, not to drive an energy transition. It is designed to be a practical and affordable Clean Air Act rule, not an energy policy. There are some who contend that the EPA should have pushed farther, given that the agency has legal authority, Congress will not act, we need very significant reductions to address climate change, and the EPA will be criticized for killing jobs and coal no matter what the rule actually contains. The EPA, however, designed the rule to stay within the confines of the CAA, achieve cost-effective and substantial CO

2 reductions, and put us on a path

that could achieve significantly more.

The 111(d) rule is not cap-and-trade, and it is not aimed at a particular goal (despite the fact that the cumulative reductions states would achieve under the proposed rule – roughly 30% below 2005 levels by 2030 – were calculated and announced). Rather, the state goals were established from the bottom up, by looking at how the energy world works and applying the “best system of emission reduc-tion” (BSER) in a practical way to each state’s energy situation, based on what is already being done in the state, what technology is readily available and practical, and what the state says it is planning to do.

The EPA determined that BSER consisted of 4 “building blocks”: (1) improving plants’ heat rate, (2) shifting dispatch from coal-, oil-, and natural gas-fired steam generation to natural gas com-bined cycle (NGCC) generation, (3) increasing renewable energy and nuclear generation and avoiding retirement of some existing nuclear units, and (4) increasing demand-side energy efficiency. The EPA thus did not limit the scope of its proposed rule to “inside the fenceline” actions (i.e., actions at the power plant itself), as the emission reductions achievable are much greater and more cost-effective when one also includes “outside the fenceline” measures (i.e., actions taken beyond the power plant that have the effect of reducing required emissions from the power plant).

The proposed rule would set an individualized rate-based carbon intensity goal (pounds of CO

2 per MWh) for each state to reach in

2030, thereby giving states the opportunity to think more long-term


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and to factor carbon emissions into the existing trends in the energy world. The rule would also set an interim goal for each state that represents the 10-year average emissions rate from 2020-2029, which would drive states to make decisions and reductions earlier and give them check-in points to make sure they will meet the 2030 goals.

While the BSER building blocks were used to come up with each state’s goal, states do not need to use the building blocks in the way the EPA calculated – or even use them at all – in putting together their implementation plans. Since resources, options, and costs will vary from state to state, the rule proposes to give states enormous flexibility to chart their own destinies. Efforts underway in states to remake the grid could be part of state plans, as they drive changes in managing demand and achieving reductions. The EPA will also put something out soon that recognizes some biomass feedstocks as compliance options under the rule. In addition, the proposed rule recognizes nuclear power as part of the zero-carbon energy genera-tion mix and calls attention to the fact that some plants are aging and non-competitive, which means if those plants end up getting retired, states will have a lot of zero-carbon ground to make up.

The EPA made clear in the draft rule that states could pursue regional opportunities to achieve compliance, which could be easier and cheaper for some states. However, states are not limited sim-ply to a Regional Greenhouse Gas Initiative (RGGI) type of model; they could do any regional arrangement that makes sense for them (e.g., just renewables). States get extra time to submit plans if the states need new legislation or regulations or are pursuing multi-state programs.

The EPA’s approach is somewhat modeled on the strategy of adaptive management used in the natural resources arena – namely, states have a goal they are trying to achieve, they can try things to reach it, and if those do not work, they can try something else. The rule does not try to set everything in stone through 2030. For instance, given that smart technologies are infusing themselves into the energy sector at an increasingly fast pace, states will need to be able to update their plans to reflect the latest technologies. States


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have the ability to change course and pursue new opportunities, as long as they provide an analytical basis showing achievement of at least the same level of reductions.

States really are in the driver’s seat, but whatever they choose to submit in their compliance plans, and as much flexibility as they have to figure out the path forward, the draft rule proposes to have those efforts be federally enforceable under the Clean Air Act.

The EPA makes clear in the proposed rule that it welcomes com-ment on a wide range of topics, from fundamental principles about the overall framework to the data used in calculating each state’s goal.

Confusion and Concerns about the Rule

The proposed rule has triggered a fair amount of confusion and concern. For instance:

• Some leading states complain that the EPA did not recognize their leadership in reducing emissions, though the EPA tried to give states credit for existing action and leadership.

• Some states are expressing concern about fuel diversity, though the EPA tried to factor that into the targets and enable states to make the choices they think make the most sense.

• Some readers of the rule are getting confused in thinking that the “building blocks” that make up BSER are require-ments for the states. There are also concerns that some of the building blocks’ assumptions will be difficult, costly, or dis-ruptive to achieve in reality. The building blocks, however, are just what the EPA thinks states can reasonably achieve and were used to develop each state’s target. The strategies states actually pursue for compliance are totally up to them (short of using offsets, as the goal is carbon reduction from fossil-fueled power plants). If some states find particular approaches to be too expensive or unworkable, they can try to achieve reductions in other ways.


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• There are concerns about the rule significantly underestimat-ing the potential for renewable energy and energy efficiency, making very conservative estimates – sometimes below states’ own targets. It is worth noting, though, that every state defines renewable energy differently, and some parts of those definitions do not actually affect carbon pollution from power plants. Furthermore, some states will need time to build up energy efficiency infrastructure.

• There is some confusion about how the interstate nature of renewable energy (e.g., out-of-state renewable energy pur-chases) will be squared with a state-based compliance mecha-nism. States will have to work out the allocation issues when they submit their plans or form regional agreements (though if they do not, then the EPA will).

• There is confusion about the role of hydropower in comply-ing with the rule, including the fact that there is ample oppor-tunity for repowering in hydro that does not appear to have been considered by the EPA. The EPA welcomes comments on hydropower’s role.

• There are concerns about whether the 111(d) rule could undermine utilities’ existing efforts to comply with earlier EPA rules. The EPA factored all existing rules and efforts into the states’ trajectories, and future planned and potential regulations (e.g., methane, coal ash, effluent guidelines) will not be blind to what came before or what is coming after.

• There are concerns about how the EPA will enforce the rule’s obligations, as the “outside the fenceline” approach means there are potentially many responsible actors – and indeed the EPA teed that issue up in the rule, is soliciting feedback, and would like states to explain how they want to allocate responsibility.

• There are concerns that the rule relies heavily on natural gas, which is only viable if additional work is done to resolve issues such as methane leakage and groundwater contamination.


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• There are concerns that the rule will drive the system toward environmental dispatch of the generation fleet as opposed to the current system of economic dispatch, which will raise real coordination issues. The system has been doing envi-ronmental dispatch under the CAA for 40 years, though, by incorporating prices for pollutants as a cost in the normal economic dispatch. Some Regional Transmission Organizations (RTOs) may be interested in incorporating a shadow price on carbon in their models and still do eco-nomic dispatch – but that involves a somewhat unspoken need for some kind of price on carbon and may run afoul of issues in the Federal Power Act.

• There is concern that the rule might drive things faster than inertia – in machines and mechanical systems, as well as in economic and regulatory policies – can be overcome.

• There are some concerns that smaller players (e.g., co-ops) may get outgunned in the fights that will likely occur among utilities (and other stakeholders) within states when they put their implementation plans together. There will also be fights that break out among state agencies and consumer advocates, which utilities will have to deal with on an ongoing basis.

Impacts the Proposed Rule Has Already Had

Even in its draft form, the proposed rule has already had some beneficial impacts. For instance, internationally, the rule has been very well received as a sign of U.S. leadership on climate change and may well spur action by China, both of which could aid interna-tional negotiations.

Domestically, the rule has helped unstick conversations on cli-mate action and clean energy that have been stuck for years. There are now opportunities to talk about clean energy in every state. States are also now having conversations with longer planning hori-zons, as the rule sets targets for 2030. Some states have already put in a lot of work on how energy efficiency, renewable energy, and cli-


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mate programs might work within states and across regions, which will inform their discussions and compliance plans. Some states and regions are also fostering conversations between environment commissioners and utilities commissioners, which can be helpful. Public Utilities Commissions (PUCs) will be convening meetings to talk about all of the issues tied up in crafting 111(d) implementation plans, such as non-competitive nuclear plants, dispatch of power, and whether legislative fixes (e.g., to state renewables and efficiency standards) will be needed as part of a grand bargain.

This activity reveals a clear disconnect between politics and the practical, as even states that have governors who have been out-spoken in their opposition to EPA’s rule also have state officials trying to figure out how to make it work and what the best options are going forward. The 111(d) rule is unleashing a lot of creative and collaborative thinking that can be embraced by states if they so choose; it depends whether politics trumps the substantive policy opportunities.

Recommendations for the EPA

Despite the EPA’s promotion of regional opportunities, it is possible that collaboration among states could be difficult. For instance, there will be contentious issues about allocation of costs among states. Also, states that analyze the rule and figure out they are winners may be disinclined to coordinate with losing states. In addition, there could be state actions that disadvantage customers in other states. The EPA could consider issuing guidance that tees up some key principles for state compliance plans, such as that states have a responsibility to take account of the effects of their plans on consumers in other states. Some states would prefer the EPA not provide guidance that is too specific or prescriptive, though.

States are not the only ones with potential coordination issues. Many states are part of multiple Regional Transmission Organizations (RTOs), which make dispatch decisions for the entire RTO footprint, and the RTOs do not always get along with each


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other. Coordination among RTOs, however, will be essential to deal with issues such as the relative carbon-intensiveness of the plants each one dispatches in a state and the impacts of those decisions on a state’s achievement of its 111(d) target. RTOs are key players in making the 111(d) rule work. It could therefore be beneficial for the EPA to encourage a joint operating agreement among RTOs, perhaps at an EPA-organized RTO summit.

Furthermore, although the EPA has developed strong rela-tionships and coordinated closely with other relevant agencies – including the Federal Energy Regulatory Commission (FERC), Department of Energy (DOE), and National Renewable Energy Laboratory (NREL) – it may be valuable to arrange some other coordinating sessions. For instance, it could be helpful to have a meeting between states, the EPA, and FERC to look at what amend-ments may be needed in the Federal Power Act to ensure states have the authorities they need to implement compliance plans for the rule. The EPA and states may also need to work with the North American Electric Reliability Corporation (NERC) to ensure that state compliance plans reflect an understanding of the complexity of the electricity system and the need for reliability. There may even be a need for a broader summit that involves FERC, NERC, RTOs, and others to address a wide range of the electricity system’s attributes.

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Fuel Choices

Given that the EPA 111(d) rule is designed to follow where the energy industry is already heading, it is worth considering where exactly that is. There are many cross-currents in the industry, quite apart from EPA rules, that are having a profound impact on exist-ing facilities and future fuel choices – and will continue to do so. It is important to keep in mind, though, that most predictions about energy are wrong; projections about oil, gas, and other fuels made over the past 30 years are astonishingly different from what has actu-ally occurred.

Natural Gas and Coal

There has been a great deal of evolution in the natural gas industry over time. Gas used to be an afterthought in power generation, but conversations about generation today start with gas. The EPA also assumes heavy reliance on natural gas to achieve the 111(d) targets.

America’s gas abundance has been profound and sudden. Six years ago, the U.S. Energy Information Administration projected that the United States would have net imports of 7.8 billion cubic feet per day (bcf/d) of natural gas in 2030; its 2014 outlook now projects 9.2 bcf/d in net exports in 2030. That represents a swing of 17 bcf/d, which is the equivalent of almost two Qatars (currently the world’s second largest gas exporter). The shale revolution put an


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emphatic end to U.S. gas price volatility caused by national supply. It also made the United States more hurricane proof, as the country is no longer as reliant on its offshore gas supplies.

Gas has dominated new capacity in power generation for almost 25 years, representing 71% of new capacity since 1990. (Wind is sec-ond, though in recent years renewable energy’s share has been rising to the point that it is pretty much 50-50 with gas.) When gas prices bottomed out in the spring of 2012, gas briefly caught coal’s power generation market share, which is very price sensitive. Market shares of coal and gas have been converging for 25 years and are projected to meet in 2028 without anyone doing anything different – which in itself will get emissions a long way towards the 111(d) targets. Convergence would mean a shift of 236,000 GWh from coal to gas. If that shift is taken up by the existing NGCC fleet, that represents a 60% capacity factor and an additional gas supply of 4.5 bcf/d. There is plenty of gas available to meet that additional supply need. That gas will likely stay in the $4 to $6 price range through 2030, though if carbon capture and storage is required for gas at any point along the way, gas generation will get much more expensive.

In contrast, it is extremely unlikely that anyone will build new coal plants in the U.S., as the risk is too high. It is projected that an addi-tional 40 GW of coal-fired generation will be retired between 2014 and 2026. (The outlook for coal globally, however, is quite robust.) A lot of American eggs are being put in the natural gas basket.

Some utilities and reliability managers are nervous about the high reliance on gas, especially after the polar vortex this winter. They like being able to see the pile of coal outside the window. Their concerns generally fall into three areas: (1) the adequacy of pipeline and stor-age infrastructure (i.e., all the gas in the world does no good if it does not get to where it is needed), (2) who pays for new capacity, and (3) friction between the gas and electric business models. There are also concerns about inadequate infrastructure and future polar vortexes leading to a return to volatility and high price exposure, which will lead to real problems with affordability. All of these became a big deal in the winter of 2013-2014, and a range of efforts are underway

Fuel Choices

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to try to address them, including by the New England Governors and by FERC and the North American Energy Standards Board (NAESB). Gas system issues have historically been poor cousins in electricity discussions, but the near-term future of electricity seems to involve a lot of natural gas, so gas and electricity system planning will need to get much more integrated.

An additional risk from putting so many eggs in the natural gas basket is the potential for states and/or the federal government – even local governments in some states – to adopt new regulations that could stop or severely limit fracking. The reality so far has been that the industry could not have done a worse job of getting in front of the fracking issues – and continues to do itself no favors when it pushes for rights to develop near neighborhoods and schools. There are tremendous technologies and controls out there for fracking, but fracking’s future ultimately depends on public trust (i.e., social license to operate) and effective, appropriate regulation.

America’s gas abundance has also led to questions about liquefied natural gas (LNG) exports, which are controversial. Applications to DOE exceed 35 bcf/d for new liquefaction, but experts suggest that the whole world only needs about 30 bcf/d of new capacity from all exporting countries (and there is a lot of competition), which means that 10-12 bcf/d is the most likely level of real U.S. projects, leading to about 9 bcf/d of exports. The U.S. can serve that level of export demand without breaking a sweat and most likely with stable prices. The risk is probably small that connecting the U.S. to the global market could result in the global gas price pushing the U.S. price up, though when Australia did a massive push on LNG exports, the price of its domestic gas tripled. Regardless, the U.S. is already somewhat connected to global prices anyway (e.g., contracts with the price tied to Brent instead of Henry Hub).

Natural gas is gaining ground because it is so inexpensive, but it is also promoted as part of the climate solution – and there are some concerns about natural gas from a climate perspective. With respect to LNG, the energy needed for liquefaction reduces the advantage

The Future of the U.S. Electricity Sector

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of natural gas over coal. More broadly, the methane leakage issue

pervades everything about natural gas and has to be resolved if gas

is to have any credibility as a climate solution. The EPA will have to

make decisions this fall about what to do on methane, but causes

for optimism is that the solutions to the problem are pretty well

understood, the technology is pretty basic, and a good portion of

the answer is just better leak detection and repair. There is also a

need for policy and regulatory change on the gas distribution side,

where regulators have not pushed local distribution companies to

invest in upgrades and have been allowing a rate of return on “lost”

and unused gas. In addition, there is concern that we could start

building new gas infrastructure that is not “renewables-ready” – i.e.,

that exhibits operating characteristics that could be an obstacle to

integrating renewable energy instead of characteristics that could

complement renewables.

Apart from the climate issues, however, gas is undeniably much

cleaner than coal when it comes to SOx, NOx, mercury, and other

pollutants.

Renewable / Gas Synergies

In most places, the U.S. power system of the 21st century will

depend heavily on both natural gas and renewable energy sources.

Over the last few years, as noted, gas and renewables have each rep-

resented about 50% of new capacity market share, and projections

suggest the bulk of power generation investments through 2035 will

be in renewables and gas (particularly given that 70-80% of the cur-

rent generation fleet will be ready for retirement in the next 20-30

years). Energy produced from renewable sources is now around 100

GW a year globally. More than half of U.S. states have renewable

portfolio standards. Prices for renewables have come down a lot,

and technological and business model innovations have been accel-

erating. Modern wind turbines and next generation solar inverters

will be providing grid services.

Fuel Choices

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Models for achieving significant CO2 reductions by 2030 and

2050 while meeting electricity reliability requirements in a least-cost way show very big contributions from gas and renewables. This does not necessarily mean that renewables and gas will stay in a 1:1 ratio. While gas can provide the nimble, fast ramping complement to renewables, analyses show that very high levels of renewable gen-eration could be achieved by 2050 (while meeting reliability require-ments) with a relatively small amount of natural gas as backup. As renewable energy proliferates, it starts to achieve enough geographic diversity that renewables can start substituting for other renewables within a bigger balancing area. Even in high renewables scenarios, though, the need for flexibility and reliability necessitates some other generators in the fleet.

Gas and renewables potentially complement each other well over the near- and long-term in several areas, such as fuel supply, policy risk, and grid services. In the bulk energy sector, it is worth noting that the first concentrated solar plant in California was a gas-solar hybrid, and new hybrids are emerging (as are new financial syner-gies). In residential energy markets, gas-renewable hybrids have lots of upside opportunities with regard to resilience, affordability, and reliability, though there are regulatory and policy challenges.

Opportunities thus clearly exist for natural gas and renewable energy to be integrated at multiple levels, with potential partner-ships around hybrid technologies, co-optimized systems integra-tion, energy and security public policy goals, and other areas. But the market needs to value ramping service – or else no financially viable system will be feasible going forward.

Nuclear

If the EPA’s 111(d) rule is building on what is happening anyway in the U.S. energy sector, it is really unclear what that ‘business-as-usual’ means when it comes to nuclear power. There is massive uncertainty – nuclear could disappear entirely, become the biggest source of electricity supply, or anything in between.


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Nuclear power now provides about 20% of U.S. electricity – not because of new build but because of impressive capacity improve-ments at existing facilities. But continued operation of some exist-ing nuclear plants is severely pressured by low natural gas prices, with 6% of the fleet at risk. Some plants have already been retired because of high repair or environmental costs or because of eco-nomic reasons. The wind production tax credit is playing almost no role in forcing nuclear retirements. Similarly, the environmen-tal community in the U.S. has played virtually no role in nuclear power’s current problems; there are other places in the world that are backing away from nuclear due to strong pressure from Green parties, but in the U.S. the key determinant was low natural gas prices (as well as gross underestimations of the cost of new nuclear).

Most of the current U.S. nuclear fleet has been renewed, adding a 20-year extension to the original 40-year license. Several more units will be applying for renewal soon. There is an important question about whether existing plants should get their lives extended to 80 years (i.e., a second 20-year extension). The Nuclear Regulatory Commission will never approve such an extension just for carbon reasons; it has to assure itself that there will be no safety issues due to aging of the units, and it will take increasing levels of investment to keep these older plants operating safely, including new instrumenta-tion and controls.

Views on the extension to 80 years depend somewhat on one’s optimism about new nuclear plants – if one is pessimistic about the likelihood of new nuclear plants in the U.S., then the license renewal to 80 years becomes very important. After a hiatus of nearly 30 years, 2007-2009 saw a “nuclear renaissance” in the U.S., with a surge of applications for new nuclear plants (during a time of high natural gas prices). Since 2008, natural gas prices have dropped, causing a significant pullback (a “nuclear retreat”), with some appli-cations cancelled and others suspended or slowed. Momentum in the U.S. has also slowed on small modular reactors, which at one point were touted as addressing concerns about high capital costs, site selection, and water use. (In some other parts of the world, though, concerns about energy supply are so high that new nuclear

Fuel Choices

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plants are indeed getting built – in the United Kingdom, central Europe, Turkey, China, Vietnam, and elsewhere.)

So nuclear’s future in the U.S. is very uncertain, reliant on factors including whether a premium is paid for electricity fuel diversity, what natural gas price projections are, whether there is a price on carbon, whether workable capacity markets are in place, whether the units currently under construction are successful with regard to cost and timing, whether nuclear plants are able to secure long-term contracts, the degree of certainty on cost recovery, and water availability.

Energy Efficiency

Energy efficiency cannot be forgotten in a conversation about fuel choices, as it is the cheapest, most abundant, most readily avail-able fuel source there is. It has no footprint, little risk, and costs that are even lower than natural gas. There are efficiency opportunities everywhere in the country. Customers win, providers of efficient appliances and services win, and the cost of the whole system goes down over time through lower demand. Many view efficiency as the first fuel to choose.

Efficiency is also a key compliance option for the EPA’s 111(d) rule; it is projected that significant energy efficiency (meeting 50% of increased demand) has the potential to reduce overall compliance costs by about 10%.

Efficiency technologies are making great strides, with efficient houses, smart appliances, synchrophasers on the grid, and other advances making the solution space even bigger. The utility indus-try invests about $6 billion a year in energy efficiency, having grown significantly over the past few years. The government invests another $1 billion, and states and private actors invest still more. EPA rules will only drive those trends further. As questions rise about the rationale for investing huge sums in risky new traditional generation, energy efficiency presents a low-risk incremental invest-ment opportunity.

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The rate of innovation and change on the grid has been immense, benefiting from the huge R&D budgets in the IT sector. That makes this an exciting time to think about how to redefine the grid and what it provides – and what role distributed energy resources (DER) will play.

The Changing Grid

Today’s centralized electricity grid has served us very well. It has been considered the number one engineering achievement of the 20th century. But expectations of what the grid can and should deliver are changing. The core attributes of universal access, safety, reliability, and affordability remain, but emerging attributes include environmental sustainability, resilience, flexibility, and customer control. In addition, some consumers are using new technologies to become more active in managing their energy use, and some are becoming “prosumers” (i.e., both producers and consumers). On top of that, there are pressures from aging infrastructure, minimal to declining load growth, and variable renewable energy integration.

Distributed energy resources are emerging in this context and are likely to play a critical role, though they will not replace the grid. Currently, most consumers with DER are still connected to and reliant on the grid, as they do not always produce power at the

Distributed Energy Resources

and the Grid


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time they need to consume it; the grid is the silent partner to DER. The grid provides startup power, voltage quality, 24/7 support, flexibility, and a range of other services that consumers have never had to think about because everything was embedded in one price: dollars per kWh. As DER expands, there will be a need to figure out how to value energy, capacity, and grid services separately and ensure the grid continues to provide the reliability and convenience customers want. Technology will help variable generation provide services other than just energy, and the market will need to respect and accurately value the different services.

Basically, the grid is moving closer to something like an “energy cloud” (similar to “cloud computing”), with DER, two-way energy flows, digitalization of infrastructure, and complex market struc-tures. Integration and control of intermittent resources will grow in complexity as penetration increases, raising security and load balancing challenges.

One could envision five basic ways the grid could evolve with DER, along a spectrum of integration. The first and least integrated way would be with grid defection and islands of self-generation, which has already happened here and there. A second way would be to have DER connected to the grid but not particularly integrated into it, which is basically where we are today; this current model risks enabling individual choices that are beneficial for consum-ers but have negative spillover effects on the system. A third way involves connection rules that require DER to provide grid voltage services. Fourth on the spectrum would be beginning to plan and integrate with a Distribution System Operator, including guided deployment of DER. The fifth would be a fully integrated grid, with DER operators in constant contact with system operators, maxi-mized use of assets, and efficient use of capital and resources. Places that have very little DER penetration at this point may be able to skip some of the earlier ways and leapfrog to a model that values all the services and guides DER deployment.

To get to an integrated grid, though, there will have to be grid modernization (e.g., new dynamic controls), communication stan-

dards and interconnection rules, integrated planning and opera-tions (including physical and cyber security), informed policy and regulation, fair allocation of costs, fair compensation for services provided, enhanced ability to manage big data, and an intense focus on responding to and anticipating the needs of customers. An inte-grated grid could surpass our current standards of reliability, afford-ability, safety, resilience, and environmental stewardship while enabling customer choice.

To get started, it is possible that the introduction of new mecha-nisms and markets to integrate DER may need to be staged, open-ing the doors first where there are the biggest values on the table, in order to ensure that the markets are truly animated from the beginning. Another option is for regulators to set particular goals for distribution utilities (e.g., shave peak by 10%) and to leave it to the utilities to figure out the best ways to get there. Either way, it is important to figure out what needs to be set up on Day 1 to really get markets for DER going.

DER Technologies

While additional technological investments and innovations are still needed in DER, it may be time to stop talking about whether the technology exists and whether we should have an integrated grid. Most seem to agree that it does (or is on its way) and we should. While a lot of the industry does not have much experience with some of these technologies yet, many technologies have moved even faster than anticipated and are here now.

Demand response, for instance, is an effective alternative to capacity expansion, provides great flexibility to system operators, offers valuable reliability benefits, and has really taken off. There is a bit of a challenge in the fact that increasing market penetration of renewable energy may push the need for demand response into the hours (roughly 4pm–9pm) when it is hardest to ask consumers to curtail their energy use, but there are available technologies and programs that could enable customers to shift their load.

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Distributed Energy Resources and the Grid


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Solar PV is also on an impressive trajectory. It represented 74% of new U.S. electric generating capacity in the first quarter of 2014, though that is primarily due to utility-scale solar. (Solar is also still only 1% of total U.S. generating capacity.) It is projected that total U.S. installed solar capacity in 2020 will be almost 70 GW (up from less than 20 GW today), of which 60% will be distributed. Solar power in particular raises questions about the ways in which subsi-dies and other measures can affect development of energy resources, given that more solar can generally get built faster and cheaper at utility scale and/or with ground mount than on rooftops, yet net metering policies provide a large incentive for rooftop solar. Part of the reason for that, though, may be that views of what the “product” is can be broadened beyond just interchangeable kilowatt-hours. Rooftop solar can meet a range of customer interests and desires; it can be marketed successfully to environmentalists who care about climate change and to libertarian survivalists who want indepen-dence and distrust monopolies. Community solar, too, is more than just kWh; it is an alternative product for consumers who do not want to put things on their roofs (for any number of reasons) but want a low-cost, fixed-price, flexible, no-contract way to displace fossil fuels and want renewables sited in their community (without building transmission).

Electric vehicle sales have also been rising rapidly and have pene-trated faster than hybrids, though overall sales are still small. As EVs become much more prevalent, there is the potential for increased vehicle storage and vehicle-to-grid (V2G) technologies that could provide new opportunities for grid management, if the right policies are put in place ahead of time.

Advanced metering infrastructure deployment has fallen from its stimulus peak but is still strong, with over 50 million units deployed. The European Union is also doing a two-year study on smart meters to see if smart inverters can bring reactive power and voltage con-trol. Already, the “enernet” (energy + internet) is starting to appear, with the electricity industry chasing “big data” and trying to figure out what to do with it. (“Big data” could have applications that ben-efit both consumers and utilities, such as reducing the duration of a


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major outage.) There are also new entrants like Google looking at creating a very consumer-centric “convenient home” with products like the Nest thermostat that can be part of an integrated system of services.

Energy storage is shaping up to be another key and growing area. There are many types of energy storage currently available, including batteries, compressed air, ice thermal, electric vehicles, and pumped hydro. Storage can be at the generation, transmission, distribution, or customer level and can provide many services, including energy shifting, ancillary services, reducing distribution load, and voltage support and inertia. California recently launched a competitive market for energy storage, with the state PUC setting a storage goal for investor-owned utilities of 1.3 GW by 2020; initial responses to utility requests have yielded an abundance of bids from a range of technologies and sizes. There are important but manageable policy issues that need to be worked out regarding integration of storage into the system, though, including resource adequacy (i.e., how storage should count towards utilities’ capacity requirements since it is both a demand for and a supply of power), storage rate structure (i.e., what a storage device should pay for power from the grid and what it should charge when it sells power), storage interconnection (i.e., whether storage counts as demand, which usually gets a free ride for interconnection, or as generation, which has to pick up some of the tab for network upgrades), and storage utilization and control (e.g., whether and how utilities can use behind-the-meter storage, and whether and how storage can be controlled by both an Independent System Operator and a utility’s grid control center).

There are also many other DER technologies, including fuel cells and microgrids. There are distributed gas generation technologies, too, though if gas is highly used for distributed generation for resi-dential and commercial markets, a lot of distribution systems would be very stressed and would need to be revamped. Also, if gas-fired gensets become more pervasive, there will be heightened concerns about the fact that they tend to be very inefficient and create a lot of air pollution and health impacts.


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Utilities, DER, and the Grid

Technology, policy, and market forces will continue to increase DER deployment and move the industry in new directions (though it is important to recognize that munis and co-ops often have differ-ent drivers and incentive structures than investor-owned utilities). Change could come quickly with new business models and regula-tory changes.

Utilities (and regulators) could embrace the opportunities pre-sented by DER. The DER technologies mentioned above, as well as others, provide benefits to the system, such as better resiliency; demand response, for instance, was a key reason that PJM could keep the lights on during the polar vortex. DER can also pro-vide improved reliability, faster restoration, reduced emissions, and enabling of innovation. DER can significantly reduce utili-ties’ investment costs, such as through better asset utilization and increased use of demand response and energy efficiency. If utilities can figure out a business model for DER – and can find test cases that are compelling to them and that increase their comfort with adopting new technologies – DER can be a win for everyone.

Despite the potential for DER to be a win-win, there have been many disagreements about DER deployment and appropriate regulations, perhaps because of conflicting worldviews. Utilities are coming from the world of centralized generation, cost of service charges, the regulatory compact, and capital-intensive infrastruc-ture that needs incentives to draw in private capital. This is where we have been for more than 100 years. DER advocates, on the other hand, are coming from a world of distributed infrastructure, more localized benefits, monopolies as market obstacles, and no need for capital incentives because capital already wants to get into the market but cannot. Utilities are focusing primarily on today’s legacy system, while DER advocates are generally focusing on the system they want to see in the future. There are particular struggles, it seems, with the rooftop solar trend, with utilities concerned about protecting their customer bases (especially low-income) and their business (especially with regard to getting paid for the cost of


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transmission and distribution services). No one has really come up with a “best regulatory model” to both promote rooftop solar and address utility concerns, though there are some ideas out there (e.g., coming up with an overall “value of solar”, instituting higher fixed fees and lower variable fees, having an integrated distribution resource plan, buying the inverter from the customer to better con-trol voltage quality and outflow to substations).

There are a variety of models being discussed for how best to structure the broader distribution market platform. On a continu-um from most aggressive to least aggressive, these include:

1. Having independent distribution grid operators, modeled after RTOs, creating markets welcoming to all market partici-pants (i.e., competition-friendly platforms). Independence would mean the operator would be fair to all, but the down-side is that local distribution companies are the ones that know the most about their wires and systems.

2. Allowing distribution owners and operators to be one and the same, but limiting the wires owners to just the wires function. In other words, wires owners could not compete for services in their own territories. They could compete through affili-ates in other service territories, but not in their own.

3. Allowing distribution operators to also be market par-ticipants, offering services in their own systems. This would require separation of the wires function and safeguards against affiliate preferences.

4. Putting distribution operators in charge of meeting defined goals for energy efficiency and distributed generation, but all through competitive procurement processes.

5. Putting distribution operators in charge of meeting defined goals for energy efficiency and distributed generation in whatever manner they deem appropriate – they could pro-vide services themselves or provide them bilaterally or com-petitively.


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There is also an idea that perhaps some of the disagreements between utilities, DER advocates, and others can be avoided by agreeing on some first principles about DER and the roles of utili-ties (or, at least, investor-owned utilities), as a foundation for taking action. Possible principles include the following:

1. Create both short- and long-term frameworks and create a glide path to get from the short-term to the long-term. We have a sys-tem now that we must be committed to maintaining and keep-ing reliable. In the long-term, we must be committed to cap-turing new technologies, but if we do it too slowly and poorly, it will be very expensive. Therefore, we need a glide path.

2. Ensure U.S. electricity consumers have a safe and reliable source of electricity at a reasonable cost, but recognize that with appro-priate safeguards, economic regulation (and the regulatory com-pact) may not be the only means to accomplish this goal. Safe, reliable, and reasonable cost cannot go away, but there may be other ways of ensuring those attributes.

3. Retain the natural monopoly from the distribution substation to the meter (but not the data); this infrastructure will remain with the incumbent utility. This may be part of a long-term vision, though there are important questions around what the scope of the natural monopoly ought to be. The custom-ers will own most of their data, though utilities use some of the data to operate the system.

4. Allow a fair opportunity for new DER technologies to enter and compete in the market, including storage, distributed genera-tion, demand response and energy efficiency, microgrids, electric vehicles, technologies that increase efficient use of existing assets (e.g., by reducing losses), and flexible reserves for integration of variable energy resources such as wind and solar. There are important questions, though, about what “fair” means (as it is often in the eye of the beholder) and about how a microgrid is defined (e.g., whether it can grow so big as to be a competitor to utilities). Also, if people are relying on the grid, they should certainly have to pay for it.


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5. Allow public utilities (or, if in a holding company structure, the parent corporation) to compete in this marketplace, thereby allow-ing them, if well managed, to earn a reasonable profit. Many util-ity executives want to be part of DER and even be leaders, and it is possible that DER deployment will go more slowly if they do not lead. If a utility can do DER well and cost-competitively, let them compete. This does not mean the delivery company, though; it means an affiliated company. Affiliates ought to be able to do business on their own system. If this truly becomes a competitive market, though, then it is important to realize that utilities can also fail. In addition, there are decisions to be made about whether utilities could invest in distributed generation on the rate-base side of the business.

6. Ensure the building of infrastructure that is necessary for our nation’s prosperity. There are questions, however, about how exactly to do this and whether a state should do something for “our nation’s prosperity” that is of no benefit to the state itself.

7. Facilitate the achievement of environmental goals, laws, and regulations. There are important questions, though, about whether this should go beyond environmental to include economic, energy security, and perhaps other areas, as well as about what to do in the case of goals, laws, or regulations one might want to challenge.

8. Low-income populations have a right to basic electric service (assuming that they pay at least a nominal fee). Basically, universal access must still be preserved as an important goal. There is a question, though, about whether electricity service should just be priced on a pure cost basis, with subsidization of low-income populations taking place through other means (e.g., the tax code).

9. Both shareholders and ratepayers pay for stranded assets. A corollary might be that stranded assets should be avoided as much as possible. Also, for some electricity providers (e.g., munis and co-ops), shareholders and ratepayers are the same.

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Models for Providing Energy Services

Electricity is an incredibly valuable product that people take for granted. Going forward, as the focus becomes more about services, utilities will have to find a way to make electricity interesting and bring it to customers’ attention. Utilities will also need to realign strategies and business models to address the various changes in operations, customer needs and expectations, and technology.

A History of Utilities Responding to Circumstances

Utility strategies over the years have largely evolved in response to what was going on in the world and what the industry had done before.

In the 1960s, the industry saw rising demand, declining costs, and optimistic regulations, and so utilities’ signature strategy was to build (e.g., big coal and nuclear plants). In the 1970s, everything went a different direction, especially after the 1973 oil embargo, and the industry saw fuel price shocks, stagflation, collapsing demand, and contentious regulation; the signature strategy then was to can-cel projects. The 1980s started with a hangover from the 1970s, with the industry traumatized by the realization that it could spend tons of money on projects that would never get built, and so the signature strategy was to diversify; utilities bought banks, insurance companies, real estate companies, and other unrelated ventures that


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utilities had little experience with (and to which they could make few contributions). In the 1990s, utilities were chastened by their experiences with diversification, but oil prices had stabilized, energy markets were liberalizing, markets in the U.S. and abroad were being restructured, people were feeling confident, and regulators were skeptical about the regulated model – and so the signature strategy was to build, buy (e.g., systems abroad), and trade within the indus-try. Trading did not work out so well, as the world saw with Enron. In the first decade of the 21st century, there was the financial crisis, and the signature strategy was to go back to basics to run a solid company and control costs. In all these decades, smart people with responsibilities to customers were trying to respond to events to craft a strategy to prosper, survive, and grow. None of these events fundamentally changed the business, though. Things got rearranged within the industry, but the fundamental relationship of supplier, distributor, etc. did not change much.

Challenges to the Current Utility Business Model

In the second decade of the 21st century – now – there are a range of factors in play. Environmental regulations, like 111(d), are a big deal but do not fundamentally change the underlying business of utilities. Financial markets, too, are changing, but they do not yet pose major threats to the utility business model. While there are some investors who think utilities are dinosaurs, investor appetites generally remain strong, there is value and trust in the utility fran-chise, and there is a trend toward pure-play investing.

There are, however, two factors that are fundamentally changing the nature of the business. First, the industry is facing slowing retail electricity sales growth. In 1980, the relationship between GDP growth and electricity sales growth was 1:1, but electricity consump-tion intensity has been decoupling since then, and electricity con-sumption has basically been flat since 2006. That is a fundamental change – that is revenue that is not coming in. At the same time, people’s reliance on electricity is greater than ever.


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Second, and related to the first, technology is creating competi-tion, with efficient buildings, efficient appliances, LED lighting, solar power, and other technologies giving people the services they want while taking significant amounts of load (and thus revenue) away from utilities. Companies in the technology space are increasingly trying to get into the game of providing comfort and other things customers desire, and these companies could be either competitors or partners for utilities. Utilities need to stay engaged, understand the technologies, and try to get ahead of (rather than be defined by) technological and regulatory issues, though it can be hard to predict which technologies will actually be viable.

Given these game changers, plus increasing grid investment, the signature strategy so far this decade has been enterprise risk manage-ment. For instance, there has been a lot of merger activity as com-panies try to get bigger to achieve diversity of generation portfolios, regulatory regimes, political systems, climates, and customer bases.

In addition to consolidation, utilities need to start behaving as if they need to win their customers; companies that do not know what their customers want fail. There could be a wide range of customer segments for utilities to serve, including millennials and younger people (who tend to like new, shiny, mobile things and assume that utilities are far more technologically advanced than they actually are), higher-income people with social consciousness (who tend to be willing to spend more if their electricity is carbon-free and reduc-es pollution in the community), middle- and low-income people (who tend to be busy doing their jobs and living their lives and just want low prices and systems they do not have to pay attention to), and libertarian survivalists (who tend to associate distributed gen-eration with freedom). Utilities can never stop analyzing customers’ behaviors and preferences – and what competitors are offering to customers. It is challenging, though, for utilities to understand and respond to customer choice. For over 100 years, utilities have been largely made up of engineers who knew the customer would pay at the end of the line, so a lot of people in utilities have not thought much about customer choice and customer experience, and they


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have limited familiarity with innovation, business development, marketing, and the like.

Once utilities get a sense of what customers want and need, they then have to figure out if they can meet those needs with any kind of competitive advantage, skill, or expertise; it is important for utilities to know who they are and what they are good at, so they know what pitches not to swing at. Utilities then have to work with regulators to make sure the rules allow utilities to meet those needs and get revenue, including possibly transitioning from consumption-based rates to more fixed costs.

Utilities’ strategies basically can be categorized as defense or offense. To play defense, utilities can engage with customers and regulators to understand customer choice, improve customer ser-vice and reliability (e.g., grid hardening) at the lowest rates possible, charge net metering customers for transmission and distribution services, help customers save money with demand response and energy efficiency tools, and develop utility owned renewable energy assets for environmentally-conscious customers. To play offense, however, is a different game that takes a broader view of the land-scape to understand regulations, competition, and technologies. On offense, utilities can think about new revenue streams, new business models, new products and services, transformed organizational cul-ture (not an easy thing to accomplish), and new executives that can both market to customers and understand the realities of the utility world. They also can start building their branding with customers, which is a clear advantage for incumbent utilities; customers may hate them, but they trust them.

Emerging Utility Business Models

Given declining energy consumption, technological competition, environmental regulation, and other factors prevalent this decade, utilities face challenging decisions about what business models to adopt and what to invest in. It will take some time for utilities to figure out what their new business models are, and it will be a messy,


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jurisdiction-by-jurisdiction process. Utilities will also be trying to sort this out while making decisions about aging infrastructure and working with states to develop 111(d) compliance plans; they have to be careful not to make decisions that have the effect of blocking new business models from emerging.

The risk-reward scenarios for new generation facilities are not very appealing, raising the question of who – if anyone – will actu-ally invest in new central station generation again. The risk-return profile is much better for utilities on distribution than on generation.

Utilities need to find ways to create new revenue streams and offer new products and services to customers. Utilities could become developers, owners, and operators (alone or through part-nerships) for many technologies, from rooftop and community solar to in-home management systems. They could provide new products, services, and financing for energy efficiency, demand response, and other DER. They could offer energy saving services within their regulated business for portions of the markets that will not otherwise respond to energy service companies (ESCOs). They could sell data to third parties about the best places in their systems to put DER. They could present themselves as offering bill management services. They could offer space conditioning services for a set fee per month instead of a per kWh charge. They could try to secure an arrangement whereby they get a fee for helping to bring together transactions between consumers and producers on a transmission and distribution platform with millions of customers with generation and demand response. And the ideas for new utility business models are in no way limited to the residential sector; there are natural opportunities in the commercial and industrial sectors too, which is where more of the money is.

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Regulation

New business models are not just about the utilities. There is a larger conversation to be had with a broad set of stakeholders about the overall social and regulatory compact related to electricity ser-vice. With so many changes already happening in the industry, there is an opportunity to work through the issues and have conversations. Regulators can facilitate those conversations and the new business models – or they can get in the way. Regulators can be both agents of and obstacles to change. There is a need to think hard about the role of regulators in terms of leading and following.

Regulators as Obstacles to Change

Current regulatory models, practices, and processes are lagging behind emerging technologies and generation options. There are many reasons for this, but they all come down to this: the practicali-ties get in the way of change.

Current Public Utilities Commission appointment practices – or, in some states, commissioner elections – result in a lot of people on commissions who are new to the business and learning on the job, and there is hardly a business more complicated than this. They are also term-limited. This means the people on the PUC staff are the real knowledge experts, but they often have never had any other job but being PUC staff, so they bring a limited range of experience.


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PUC staff also often engender a culture of distrust, with the view that utilities are scheming and Machiavellian. Commissioners, as short-timers, really cannot change the overall office culture. In addition, there are jurisdictional silos among executive branch agen-cies that are rarely breached.

The realities of the law and practice of regulation can pose hurdles as well. Innovation and experimentation are constrained by more than 100 years of legal precedent. Commissions are also very differ-ent in their authorities, with some empowered to do more than oth-ers. Debates about PUC action are often so grounded in consumer advocacy concerns – i.e., concerns about poorer ratepayers paying too much – that discussions about actual “value of service” are rare. Administrative procedures and practices tend to move very slowly and are heavily influenced by the realities of who has the means and interest to shows up.

There are also the politics of regulation to contend with. Everyone always wants to claim credit. Regulators have a hard time letting go of the old ways of doing things. They have very few incentives for taking risks. Lowest-common-denominator politics tends to dominate. The goals set for electricity service are inherently schizophrenic, with providers told to charge the cost of service but also give discounts for low-income customers, make new markets for storage, promote economic development, and advance envi-ronmental protection. In addition, the power of entitlement and incumbency is very strong; people do not want to change the good-ies they have (e.g., it will be very hard to ever wean the people now on net energy metering off of it). Beyond all that, we often get stuck in what is urgent versus what is important.

Regulators as Facilitators of Change

Regulators, however, can and often do play a constructive and facilitative role as well. To seize this important moment to think and lead, adapt to changing circumstances, and enable new utility business models, regulators may need to try to shed some of their

Regulation

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natural risk aversion. Regulators can pursue efforts to address things such as new rate structures (e.g., rates no longer tied to kWh), revised net-metering arrangements (e.g., to properly recover trans-mission and distribution costs), or new cost recovery strategies for potential stranded assets. They can help promote system efficiency, including end-use energy efficiency. They can help appropriately monetize the value of DER on the grid. On a grander scale, regula-tors can also pursue fundamental redesigns of the entire electricity regulatory system, such as the efforts getting underway in the UK and New York (see below).

In addition, regulators have some core functions and roles that are vital to maintain, even if in somewhat adapted form. For instance, regulators are the protectors and enforcers of the regula-tory compact, including universal access. Along those lines, there are analogies to FedEx and the US Postal Service to keep in mind. USPS was set up to let everyone have access, but the best customers started peeling off to FedEx, which left USPS as the provider of last resort, with ever increasing costs spread across a system of fewer users. In the electricity realm, regulators have to figure out how to keep a healthy provider of last resort without it becoming the worst of that world.

There is also no getting around the fact that this whole endeavor is not just about letting markets work or getting the rules just right; this is also high-order politics, which means regulators need to be savvy about how to frame the goals being pursued, who has to be satisfied, and where compromises need to be made. Industrial consumers, for instance, are a powerful force in many states, and they tend to hate variable charges to support programs for demand response, efficiency, and renewables. Regulators need to find prag-matic ways of moving forward – taking first steps, avoiding winners or losers, and creating markets.

Looking at the system more comprehensively, though, it is pos-sible that our current energy federalism structure is just too broken to actually protect the planet, protect consumers, establish vibrant markets, aggressively jumpstart energy efficiency, and remove


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barriers to new market entrants. Congress is so gridlocked it has become largely irrelevant to energy policy, which means the execu-tive branch, states, and local governments have to step in, but many of them are siloed. Judges may end up being the primary makers of energy policy, and they have the least background and training on the issues. These realities, coupled with shrinking demand, aging infrastructure, cyber and physical security threats, droughts, polar vortexes, and other factors, may suggest that, without creative and ambitious regulation, the only hope for change will be innovators, disruptive technologies, and the few market entrants that can man-age to muscle their way in.

Regulators Leading the Way: New York’s REV

New York offers a prime example of regulators leading the way with creative and ambitious regulation. New York regulators are pursuing a very ambitious agenda focused on Reforming the Energy Vision (REV), which goes beyond Utility 2.0 and instead is about fundamentally changing the industry.

REV envisions managing demand as the first resource on the grid, not the last, and having demand move to meet generation instead of the other way around. It envisions retail and wholesale markets working together. It envisions a new regulatory compact that demands that market-driven, clean-energy innovation is both in front of and behind the meter to create value for consumers. It envi-sions a consumer-centric system that gives mass market, commer-cial, and industrial consumers real choice, not just in terms of what supplier they choose, but also how they control and monetize the value of assets. It envisions a Distribution System Platform Provider that can do integrated and transparent planning for meeting future demand, operationalize efficiency and optimize load over the entire system, and promote and provide product and service innovation so that two-way systems are in place to ensure compensation for a range of services. REV is also focused on what New York needs to do with regard to the bulk power market to address concerns about cost of fuel, pipeline requirements, fuel diversity, and other issues.

Regulation

41

There are several outcomes expected from REV. One is market animation; rather than having system benefits charges, programs, and mandates on top of rates, REV is driving toward animating a downstream market where retailers offer bill management services. Another expected outcome is system efficiency, aiming for opti-mized use of resources, so that every dollar spent on energy is of value. Other key outcomes include reliability, resilience, and envi-ronmental and economic sustainability (driven from the standpoint of the market, not as a mandate). REV will also necessitate regula-tory change, moving toward a model that is long-term, outcome-based, and service-oriented and that achieves environmental goals, promotes energy efficiency and innovation, and allows utilities to really make money.

The REV process is on a very fast timeline. The Public Service Commission will issue a decision by the end of 2014 about the func-tion of the Distribution System Platform Provider and the role of the utility. The idea is for the Commission in early 2015 to then come up with a model for what rate plans need to contain and for utilities to file individual plans to get going in 2015.

The pioneering redesign that New York is attempting may be every bit as important and impactful as the EPA’s proposed 111(d) rule. Like 111(d), New York’s new vision is a conversation starter, not the final word. As REV is designed and implemented, it will be a learning exercise not only for New York but also for many other states, utili-ties, and stakeholders that are looking on with great interest.

Appendices

Thursday, July 3

6:30 – 9:00 PM Opening Reception and Dinner

Friday, July 4

8:00 – 11:30 AM

SESSION I: CLEAN AIR RULES, IMPLEMENTATION & COSTS

When the EPA’s CO2 rule for new plants is finalized, what guidance will

EPA issue to the states (and the industry) for existing plants? What can states do in anticipation? What are the ongoing impacts of rules for other Clean Air Act criteria pollutants? What are the likely costs of complying with various possible standards? How have past projections compared with actual costs for compliance with environmental regulations?

Chair: Sue Tierney, Managing Principal, Analysis Group

8:30 AM – 10:00AM Gina McCarthy, Administrator U.S. Environmental Protection Agency

10:30 – 12:00 PM Roger Sant, Chairman Emeritus and Co-Founder, AES

Doug Scott, Chairman, Illinois Commerce Commission

Respondents: Kevin Fitzgerald, Executive Vice President and General Counsel, Pepco Holdings, Inc.

Robert Powers, Chief Operating Officer, American Electric Power

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Agenda


46

Saturday, July 5

8:30 AM – Noon

SESSION II: FUEL CHOICES

What will happen to the resource mix in response to low gas prices, renewable energy requirements, nuclear retirements, mercury/air toxics rules, EPA GHG regulations, water requirements, and resilience and sys-tem stability needs? What is the supply, demand, and price outlook for natural gas, the risks and uncertainties, the prospects for LNG exports, and the impact on other fuels? What delivery infrastructure enhancements are needed for various fuels? How much energy efficiency and demand man-agement remains to be tapped?

Chair: Mark Brownstein, Associate Vice President and Chief Counsel, Environmental Defense Fund

Rick Smead, Managing Director, Advisory Services, RBN Energy LLC

Duane Highley, President and Chief Executive Officer, Electric Cooperatives of Arkansas

Joe Kelliher, Executive Vice President, Federal Regulatory Affairs, NextEra Energy, Inc.

Doug Arent, Executive Director, Joint Institute for Strategic Energy Analysis, National Renewable Energy Laboratory

1:30 – 5:00 PM

SESSION III: DISTRIBUTED ENERGY RESOURCES

What are the game-changing technologies on customer premises? Who is adding them? Why? What’s happening to costs? What technologies leap-frog the meter versus being dependent upon it? What system integration issues result? Who is installing microgrids? Why? What are their impacts on distribution system operations and investment needs? How fast is a transition occurring? Is it entirely dependent on net metering?

Chair: Philip Mezey, President and Chief Executive Officer, Itron, Inc.

Stuart Hemphill, Senior Vice President, Power Supply, Southern California Edison

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Agenda

Malcolm Woolf, Senior Vice President, Policy and Government Affairs, Advanced Energy Economy

Anda Ray, Vice President, Environment and Chief Sustainability Officer, Electric Power Research Institute

Lauren Azar, Lawyer, Azar Law LLC

Sunday, July 6

8:30 AM – Noon

SESSION IV: MODELS FOR THE ENERGY SERVICES PLATFORM

What lessons have been learned from industry restructuring in the 1990s? What should utilities do in the face of technology innovation and adop-tion: Be enablers? Become investors? What is inevitable, and what is sub-ject to changes in regulatory models? What is motivating utility mergers? What are investors saying? What will a utility look like in five years – its roles, responsibilities, services, sources of revenue? What new skills/busi-nesses/capabilities do utilities need?

Chair: Kevin Fitzgerald, Executive Vice President and General Counsel, Pepco Holdings, Inc.

Paul Bonavia, Executive Board Chair, UNS Energy

Robert Powers, Chief Operating Officer, American Electric Power

Doyle Beneby, President and Chief Executive Officer, CPS Energy

Jan Vrins, Leader, Global Energy Practice, Navigant Consulting, Inc.

Samuel Brothwell, Senior Analyst, Energy Income Partners LLC

Monday, July 7

8:00 – 11:30 AM

SESSION V: REGULATION

What is happening to the regulatory compact? What constitutes the natural monopoly today? What does retail competition mean today? What product and service offerings and types of customer differentiation are possible? How should services be priced in an era of lower asset uti-


48

lization and less throughput? What is the State PUC role? Are there roles

for the federal government in retail changes? How are federal/state rela-

tionships changing? How are regional electricity markets doing? What is

needed to accommodate new roles for the grid in an era of dispersed and

centralized generation?

Chair: Ralph Izzo, Chairman of the Board, Chief Executive Officer and

President, Public Service Enterprise Group, Inc.

Audrey Zibelman, Chair, Department of Public Service, New York

Bill Massey, Partner, Covington and Burling LLP

Sue Tierney, Managing Principal, Analysis Group

Respondent: Joseph Kelliher, Executive Vice President,

Federal Regulatory Affairs, NextEra Energy, Inc.

Participants

49

Doug Arent Executive Director Joint Institute for Strategic Energy Analysis

National Renewable Energy Laboratory

15013 Denver West ParkwayGolden, CO 80401

Lauren Azar Azar Law LLC809 Spaight StreetMadison, WI 53703

Doyle Beneby President and Chief Executive Officer

CPS Energy145 Navarro StreetSan Antonio, TX 78205

Roger Berliner CouncilmemberMontgomery County Council100 Maryland AvenueRockville, MD 20850

Peter Blair Executive DirectorDivision on Engineering and Physical Sciences

National Academy of Sciences500 Fifth Street NWWashington, DC 20001

Paul Bonavia Executive Board ChairUNS Energy 88 East Broadway, HQE901Tucson, AZ 85701

Jason Bordoff Founding DirectorCenter on Global Energy PolicyColumbia University420 W 118th Street, Room 901FNew York, NY 10027

Samuel Brothwell Senior AnalystEnergy Income Partners LLC49 Riverside AvenueWestport, CT 6880


50

Mark Brownstein Associate Vice President and Chief Counsel

Environmental Defense Fund257 Park Avenue SouthNew York, NY 10010

Sandra Byrd Vice President, Public Affairs and Member Services

Arkansas Electric Cooperative Corporation

PO Box 194208Little Rock, AR 72219

Kateri Callahan PresidentAlliance to Save Energy1850 M Street NW, Suite 1050Washington, DC 20036

Bradley Campbell PresidentSwan Creek Energy50 West State Street, Suite 1100Trenton, NJ 8608

Edward Comer Vice President, General Counsel and Corporate Secretary

Edison Electric Institute701 Pennsylvania Avenue NWWashington, DC 20004

Celia David DirectorNavigant30 South Wacker DriveChicago, IL 60606

Reid Detchon Vice President, Energy and Climate

United Nations Foundation1750 Pennsylvania Avenue NW, Suite 300

Washington, DC 20006

Thomas Edgar Director, Energy InstituteUniversity of Texas at Austin2304 Whitis Avenue, FAC 428, Stop C2400

Austin, TX 78742

Shelley Fidler PrincipalVan Ness Feldman1050 Thomas Jefferson Street NW


Kevin Fitzgerald Executive Vice President and General Counsel

Pepco Holdings, Inc.701 9th Street NW, EP 1007Washington, DC 20068

Michael Fitzpatrick Senior Counsel and Head of Regulatory Advocacy

General Electric Company1299 Pennsylvania Avenue NW, Suite 900


George Frampton PrincipalNewEnergyAdvisors LLC1054 31st Street NWTowpath Partners, Suite 340Washington, DC 20007

Dave Grossman (Rapporteur)PrincipalGreen Light Group820 Richmond AvenueSilver Spring, MD 20910

Jason Grumet PresidentBipartisan Policy Center1225 I Street NWWashington, DC 20005

Julia Hamm President and Chief Executive Officer

Solar Electric Power Association1220 19th Street NW, Suite 800Washington, DC 20036

Marilu Hastings Director, Sustainability Program

Cynthia and George Mitchell Foundation

2630 Exposition Boulevard, Suite 214

Austin, TX 78703

Stuart HemphillSenior Vice President, Power Supply

Senior Vice President and Chief Financial Officer, Financial and Operational Services

Southern California Edison2244 Walnut Grove AvenueRosemead, CA 91770

Duane Highley President and Chief Executive Officer

Electric Cooperatives of Arkansas

PO Box 194208Little Rock, AR 72219

Ralph Izzo Chairman of the Board, Chief Executive Officer and President

Public Service Enterprise Group, Inc.

80 Park PlazaNewark, NJ 7102

Kirk Johnson Senior Vice PresidentNational Rural Electric Cooperative Association, Inc.

4301 Wilson BoulevardArlington, VA 22203

Barbara Judge Former ChairmanUK Atomic Energy AuthorityOne Wood StreetLondon, EC2V 7WZ United Kingdom

Fred Julander PresidentJulander Energy Company9969 East Aberdeen AvenueEnglewood, CO 80111

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Participants


52

Joseph Kelliher Executive Vice President, Federal Regulatory Affairs

NextEra Energy, Inc.801 Pennsylvania Avenue NW, Suite 220


Jelynne LeBlanc Burley Executive Vice President and Chief Delivery Officer

CPS Energy145 Navarro StreetSan Antonio, TX 78205

Jan Mares Senior Policy AdvisorResources for the Future1616 P Street NWWashington, DC 20036

Cheryl Martin Acting DirectorAdvanced Research Projects Agency – Energy

1000 Independence Avenue SW, AR-1


William Massey PartnerCovington & Burling LLP1201 Pennsylvania Avenue NWWashington, DC 20004

Gina McCarthy AdministratorU.S. Environmental Protection Agency

1200 Pennsylvania Avenue NWWashington, DC 20460

Philip Mezey President and Chief Executive Officer

Itron, Inc.2111 North Molter RoadLiberty Lake, WA 99019

Martin Milani Chief Technology OfficerNexant, Inc.1810 Gateway Drive, Suite 360San Mateo, CA 94404

Robert Mudge Principal and Chief Operational Officer

The Brattle Group1850 M Street NWWashington, DC 20036

Nelson Nease FounderNelson H. Nease, P.C.408 West 14th StreetAustin, TX 78701

James Newcomb Managing DirectorRocky Mountain Institute1820 Folsom AvenueBoulder, CO 80304

Richard Newell Director, Energy InitiativeDuke UniversityPO Box 90467Durham, NC 27708

Denton Peoples DirectorNorthWestern EnergyPO Box 4008Incline Village, NV 89450

Robert Powers Chief Operating OfficerAmerican Electric Power1 Riverside Plaza, 30th FloorColumbus, OH 43215

Anda Ray Vice President, Environment, and Chief Sustainability Officer

Electric Power Research Institute

3420 Hillview AvenuePalo Alto, CA 94303

Evan Reese, III PartnerVan Ness Feldman LLP1050 Thomas Jefferson Street NW


Roger Sant Chairman Emeritus and Co-Founder

AES2100 Pennsylvania Avenue NW, Suite 545


Doug Scott ChairmanIllinois Commerce Commission160 North LaSalle Street, Suite C-800

Chicago, IL 60601

Phil Sharp PresidentResources for the Future1616 P Street NWWashington, DC 20036

Richard Smead Managing DirectorRBN Energy LLC2323 South Shepherd Drive, Suite 1010

Houston, TX 77019

Dianne Solomon PresidentState of New Jersey Board of Public Utilities

44 South Clinton Avenue, 7th Floor

Trenton, NJ 8625

Joanne Spalding Senior Managing AttorneySierra Club85 Second StreetSan Francisco, CA 94105

James Spiers Vice President, Technology, Egineering and Economic Analysis

National Rural Electric Cooperative Association, Inc.

4301 Wilson BoulevardArlington, VA 22203

Participants

53


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Philip St Baker Chief Executive OfficerERM Power LimitedLevel 52, 111 Eagle StreetBrisbane, QLD 4000, Australia

Greg Staple Chief Executive OfficerAmerican Clean Skies Foundation

1875 Connecticut Ave NW, Suite 405


Michael Sullivan Senior Vice PresidentNexant, Inc.101 Montgomery Street, 15th Floor

San Francisco, CA 94104

Susan Tierney (Forum Chair)Managing PrincipalAnalysis Group111 Huntington Avenue, 10th Floor

Boston, MA 2199

Susan Tomasky DirectorPSEG90 Ashbourne RoadBexley, OH 43209

Barbara Tyran DirectorElectric Power Research Institute

2000 L Street NW, #805Washington, DC 20036

Clinton Vince Chair, Global Energy PracticeDentons US LLP1301 K Street NW, Suite 600 East Tower


Jan Vrins Leader, Global Energy PracticeNavigant Consulting, Inc.255 Alhambra Circle, Suite 810Coral Gables, FL 33134

Michael Webber Deputy DirectorEnergy Institute University of Texas at Austin204 East Dean Keeton Street, Stop C2200

Austin, TX 78712

Malcolm Woolf Senior Vice President, Policy and Government Affairs

Advanced Energy Economy1101 14th Street NW, Suite 1200


Audrey Zibelman ChairDepartment of Public Service, New York

Agency Building 3, Empire State Plaza

Albany, NY 12223

Participants

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Staff:

Nicole AlexievDeputy DirectorEnergy and Environment Program

Avonique (Nikki) De VignesProject AssistantEnergy and Environment Program

David MonsmaExecutive DirectorEnergy and Environment Program

Timothy OlsonSenior Project ManagerEnergy and Environment Program

John A. (Jack) RiggsSenior FellowEnergy and Environment Program


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